The process of excavating a wellbore or cutting a formation to construct a tunnel and other subterranean earthen excavations is a very interdependent process that preferably integrates and considers many variables to ensure a usable bore is constructed. As is commonly known in the art, many variables have an interactive and cumulative effect of increasing drilling costs. These variables may include formation hardness, abrasiveness, pore pressures, and formation elastic properties. In drilling wellbores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. A high percentage of the costs to drill a well are derived from interdependent operations that are time sensitive, i.e., the longer it takes to penetrate the formation being drilled, the more it costs. One of the most important factors affecting the cost of drilling a wellbore is the rate at which the formation can be penetrated by the drill bit, which typically decreases with harder and tougher formation materials and formation depth.
There are generally two categories of modern drill bits that have evolved from over a hundred years of development and untold amounts of dollars spent on the research, testing and iterative development. These are the commonly known as the fixed cutter drill bit and the roller cone drill bit. Within these two primary categories, there are a wide variety of variations, with each variation designed to drill a formation having a general range of formation properties. These two categories of drill bits generally constitute the bulk of the drill bits employed to drill oil and gas wells around the world.
Each type of drill bit is commonly used where its drilling economics are superior to the other. Roller cone drill bits can drill the entire hardness spectrum of rock formations. Thus, roller cone drill bits are generally run when encountering harder rocks where long bit life and reasonable penetration rates are important factors on the drilling economics. Fixed cutter drill bits, on the other hand, are used to drill a wide variety of formations ranging from unconsolidated and weak rocks to medium hard rocks.
In the case of creating a borehole with a roller cone type drill bit, several actions effecting rate of penetration (ROP) and bit efficiency may be occurring. The roller cone bit teeth may be cutting, milling, pulverizing, scraping, shearing, sliding over, indenting, and fracturing the formation the bit is encountering. The desired result is that formation cuttings or chips are generated and circulated to the surface by the drilling fluid. Other factors may also affect ROP, including formation structural or rock properties, pore pressure, temperature, and drilling fluid density. When a typical roller cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth point may only penetrate into the rock a very small distance, while also at least partially, plastically “working” the rock surface.
One attempt to increase the effective rate of penetration (ROP) involved high-pressure circulation of a drilling fluid as a foundation for potentially increasing ROP. It is common knowledge that hydraulic power available at the rig site vastly outweighs the power available to be employed mechanically at the drill bit. For example, modern drilling rigs capable of drilling a deep well typically have in excess of 3000 hydraulic horsepower available and can have in excess of 6000 hydraulic horsepower available while less than one-tenth of that hydraulic horsepower may be available at the drill bit. Mechanically, there may be less than 100 horsepower available at the bit/rock interface with which to mechanically drill the formation.
An additional attempt to increase ROP involved incorporating entrained abrasives in conjunction with high pressure drilling fluid (“mud”). This resulted in an abrasive laden, high velocity jet assisted drilling process. Work done by Gulf Research and Development disclosed the use of abrasive laden jet streams to cut concentric grooves in the bottom of the hole leaving concentric ridges that are then broken by the mechanical contact of the drill bit. Use of entrained abrasives in conjunction with high drilling fluid pressures caused accelerated erosion of surface equipment and an inability to control drilling mud density, among other issues. Generally, the use of entrained abrasives was considered practically and economically unfeasible. This work was summarized in the last published article titled “Development of High Pressure Abrasive-Jet Drilling,” authored by John C. Fair, Gulf Research and Development. It was published in the Journal of Petroleum Technology in the May 1981 issue, pages 1379 to 1388.
Another effort to utilize the hydraulic horsepower available at the bit incorporated the use of ultra-high pressure jet assisted drilling. A group known as FlowDril Corporation was formed to develop an ultra-high-pressure liquid jet drilling system in an attempt to increase the rate of penetration. The work was based upon U.S. Pat. No. 4,624,327 and is documented in the published article titled “Laboratory and Field Testing of an Ultra-High Pressure, Jet-Assisted Drilling System” authored by J. J. Kolle, Quest Integrated Inc., and R. Otta and D. L. Stang, FlowDril Corporation; published by SPE/IADC Drilling Conference publications paper number 22000. The cited publication disclosed that the complications of pumping and delivering ultra-high-pressure fluid from surface pumping equipment to the drill bit proved both operationally and economically unfeasible.
Another effort at increasing rates of penetration by taking advantage of hydraulic horsepower available at the bit is disclosed in U.S. Pat. No. 5,862,871. This development employed the use of a specialized nozzle to excite normally pressured drilling mud at the drill bit. The purpose of this nozzle system was to develop local pressure fluctuations and a high speed, dual jet form of hydraulic jet streams to more effectively scavenge and clean both the drill bit and the formation being drilled. It is believed that these hydraulic jets were able to penetrate the fracture plane generated by the mechanical action of the drill bit in a much more effective manner than conventional jets were able to do. ROP increases from 50% to 400% were field demonstrated and documented in the field reports titled “DualJet Nozzle Field Test Report—Security DBS/Swift Energy Company,” and “DualJet Nozzle Equipped M-1LRG Drill Bit Run”. The ability of the dual jet (“DualJet”) nozzle system to enhance the effectiveness of the drill bit action to increase the ROP required that the drill bits first initiate formation indentations, fractures, or both. These features could then be exploited by the hydraulic action of the DualJet nozzle system.
Due at least partially to the effects of overburden pressure, formations at deeper depths may be inherently tougher to drill due to changes in formation pressures and rock properties, including hardness and abrasiveness. Associated in-situ forces, rock properties, and increased drilling fluid density effects may set up a threshold point at which the drill bit drilling mechanics decrease the drilling efficiency.
Another factor adversely effecting ROP in formation drilling, especially in plastic type rock drilling, such as shale or permeable formations, is a build-up of hydraulically isolated crushed rock material, that can become either mass of reconstituted drill cuttings or a “dynamic filtercake”, on the surface being drilled, depending on the formation permeability. In the case of low permeability formations, this occurrence is predominantly a result of repeated impacting and re-compacting of previously drilled particulate material on the bottom of the hole by the bit teeth, thereby forming a false bottom. The substantially continuous process of drilling, re-compacting, removing, re-depositing and re-compacting, and drilling new material may significantly adversely effect drill bit efficiency and ROP. The re-compacted material is at least partially removed by mechanical displacement due to the cone skew of the roller cone type drill bits and partially removed by hydraulics, again emphasizing the importance of good hydraulic action and hydraulic horsepower at the bit. For hard rock bits, build-up removal by cone skew is typically reduced to near zero, which may make build-up removal substantially a function of hydraulics. In permeable formations the continuous deposition and removal of the fine cuttings forms a dynamic filtercake that can reduce the spurt loss and therefore the pore pressure in the working area of the bit. Because the pore pressure is reduced and mechanical load is increased from the pressure drop across the dynamic filtercake, drilling efficiency can be reduced.